Patent application title: WATER INJECTION SYSTEMS AND METHODS

Abstract:

There is disclosed a system comprising a well drilled into an underground
formation; a production facility at a topside of the well; a water
production facility connected to the production facility; wherein the
water production facility produces water by removing some ions and adding
an agent which increases the viscosity of the water and/or increases a
hydrocarbon recovery from the formation, and injects the water into the
well.

Claims:

1. A system comprising:a well drilled into an underground formation
comprising hydrocarbons;a production facility at a topside of the well;a
water production facility connected to the production facility;wherein
the water production facility produces water by removing some ions and
adding an agent which increases the viscosity of the water and/or
increases a hydrocarbon recovery from the formation, and injects the
water into the well.

2. A system comprising:a first well drilled into an underground formation
comprising hydrocarbons;a production facility at a topside of a first
well;a water production facility connected to the production facility;a
second well drilled into the underground formation;wherein the water
production facility produces water by removing some ions and adding an
agent which increases the viscosity of the water and/or increases a
hydrocarbon recovery from the formation, and injects the water into the
second well and into the underground formation.

3. The system of claim 2, wherein the first well is a distance of 50
meters to 2000 meters from the second well.

4. The system of claim 1, wherein the underground formation is beneath a
body of water.

5. The system of claim 1, wherein the production facility is floating on a
body of water, such as a production platform.

6. The system of claim 1, further comprising a water supply and a water
pumping apparatus, adapted to pump water to the water production
facility.

7. The system of claim 1, wherein the water production facility has an
input water having a total dissolved salts value of at least 15,000 parts
per million, expressed as sodium chloride dissolved.

9. The system of claim 1, wherein at least one well has been fractured
with a viscous liquid and a propping agent such as sand.

10. The system of claim 1, wherein at least one well comprises a diameter
from 10 to 25 cm.

11. A method comprising:removing some ions from water;adding an agent to
the water which increases the viscosity of the water and/or increases
hydrocarbon recovery from an underground formation comprising
hydrocarbons; andinjecting the water with the agent into the underground
formation.

12. The method of claim 11, wherein the processed water is recycled by
being produced with oil and/or gas and separated, and then re-injected
into the formation.

13. The method of claim 11, wherein one or more of aromatics, chlorinated
hydrocarbons, other hydrocarbons, water, carbon dioxide, carbon monoxide,
or mixtures thereof are mixed with the processed water prior to being
injected into the formation.

14. The method of claim 11, wherein the processed water is heated prior to
being injected into the formation.

15. The method of claim 11, wherein the processed water is heated while
within the formation.

16. The method of claim 15, wherein the processed water is heated with hot
water, steam and/or a non-aqueous liquid and/or gas injected into the
formation.

17. The method of claim 11, wherein removing some cations from water
comprises removing some divalent cations.

18. The method of claim 11, wherein removing some cations from water
comprises removing some divalent cations and then removing some
monovalent cations.

19. The method of claim 11, wherein removing some cations from water
comprises removing some divalent cations and then removing some
monovalent cations, and then adding back some divalent cations.

20. The method of claim 11, wherein another material is injected into the
formation after the processed water was injected.

21. The method of claim 20, wherein the another material is selected from
the group consisting of air, produced water, salt water, sea water, fresh
water, steam, carbon dioxide, and/or mixtures thereof.

22. The method of claim 11, wherein the processed water is injected from
10 to 100 bars above the reservoir pressure.

23. The method of claim 11, wherein the oil in the underground formation
prior to water being injected has a viscosity from 5 cp to 10,000 cp.

24. The method of claim 11, wherein the oil in the underground formation
prior to water being injected has a viscosity from 500 cp to 5,000 cp.

25. The method of claim 11, wherein the underground formation has a
permeability from 5 to 0.0001 Darcy.

26. The method of claim 11, wherein the underground formation has a
permeability from 1 to 0.001 Darcy.

27. The method of claim 11, wherein producing and/or injecting are done
into a vertical and/or a horizontal well.

28. The method of claim 11, wherein input water has a total dissolved
salts value of at least 15,000 parts per million, expressed as sodium
chloride dissolved, prior to the removing some cations from the water.

Description:

FIELD OF INVENTION

[0001]The present disclosure relates to systems and methods for injecting
water into a hydrocarbon bearing formation.

BACKGROUND

[0002]Oil accumulated within a subterranean oil-bearing formation is
recovered or produced therefrom through wells, called production wells,
drilled into the subterranean formation. A large amount of such oil may
be left in the subterranean formations if produced only by primary
depletion, i.e., where only formation energy is used to recover the oil.
Where the initial formation energy is inadequate or has become depleted,
supplemental operations, often referred to as secondary, tertiary,
enhanced or post-primary recovery operations, may be employed. In some of
these operations, a fluid is injected into the formation by pumping it
through one or more injection wells drilled into the formation, oil is
displaced within and is moved through the formation, and is produced from
one or more production wells drilled into the formation. In a particular
recovery operation of this sort, seawater, field water or field brine may
be employed as the injection fluid and the operation is referred to as a
waterflood. The injection water may be referred to as flooding liquid or
flooding water as distinguished from the in situ formation, or connate
water. Fluids injected later can be referred to as driving fluids.
Although water is the most common, injection and drive fluids can include
gaseous fluids such as air, steam, carbon dioxide, and the like.

[0003]Although conventional waterflooding is effective in obtaining
additional oil from some oil-bearing subterranean formations. In other
formations, water may have the tendency to "finger" through an
oil-bearing formation and to thus bypass substantial portions thereof. By
fingering is meant the development of unstable water stream fronts which
advance toward the production wells more rapidly than the remainder of
the flooding water. Furthermore, when fingering is encountered, the water
does not normally displace as much oil in the portions of the formations
which it contacts as it is potentially capable of displacing.

[0004]Also, waterfloods may be less effective with the more viscous oils
than with relatively nonviscous oils. The fingering and bypassing
tendencies of water may be related to the ratio of the viscosity of the
oil to the viscosity of the flooding water, and also related to fractures
and/or high permeability zones in the formation. The viscosity of these
oils varies from as low as about one or two centipoise to about 1,000
centipoise or higher. Water generally has a viscosity of about 1
centipoise at room temperature.

[0005]In order to restrict the mobility of the flooding water to no
greater than the mobility of the oil, water thickening agents have been
added to increase the viscosity of the water.

[0006]There are two principal mechanisms of enhancing the oil recovery of
an injected fluid. These methods include increasing volumetric sweep
efficiency of the injected fluid and increasing the oil displacement
efficiency by the injected fluid. Both techniques may involve the
addition of agents which modify the properties of the injected fluid.

[0007]Water may be injected by itself, or as a component of miscible or
immiscible displacement fluids. Sea water (for offshore wells) and brine
produced from the same or nearby formations (for onshore wells) may be
most commonly used as the water source.

[0008]Some injection drive fluids include water and a small amount of a
water-soluble polymer, such as a polyacrylamide.

[0009]Referring to FIG. 1, there is illustrated prior art system 100.
System 100 includes body of water 102, underground formation 104,
underground formation 106, and underground formation 108. Production
facility 110 may be provided at the surface of body of water 102. Well
112 traverses body of water 102 and formation 104, and has openings in
formation 106. A portion of formation 106 may be fractured and/or
perforated as shown at 114. Oil and gas may be produced from formation
106 through well 112, to production facility 110. Gas and liquid may be
separated from each other, gas may be stored in gas storage 116 and
liquid may be stored in liquid storage 118.

[0010]There is a need in the art for improved systems and methods for
producing oil and/or gas from a subterranean formation. In particular,
there is a need in the art for systems and methods for providing an
improved polymer flood, which achieves a desired viscosity of a flooding
fluid.

SUMMARY OF THE INVENTION

[0011]One aspect of the invention provides a method comprising removing
some ions from water; adding an agent to the water, which increases the
viscosity of the water and/or increases a hydrocarbon recovery from an
underground formation, for example a surfactant and/or an alkali; and
injecting the water with the agent into the underground formation.

[0012]One aspect of the invention provides a system comprising a well
drilled into an underground formation; a production facility at a topside
of the well; a water production facility connected to the production
facility; wherein the water production facility produces water by
removing some ions and adding an agent which increases the viscosity of
the water and/or increases a hydrocarbon recovery from the formation, and
injects the water into the well.

[0013]Another aspect of the invention provides a system comprising a first
well drilled into an underground formation; a production facility at a
topside of a first well; a water production facility connected to the
production facility; a second well drilled into the underground
formation; wherein the water production facility produces water by
removing some ions and adding an agent which increases the viscosity of
the water and/or increases a hydrocarbon recovery from the formation, and
injects the water into the second well and into the underground
formation.

[0018]In one embodiment, there is disclosed a system comprising a well
drilled into an underground formation; a production facility at a topside
of the well; a water production facility connected to the production
facility; wherein the water production facility produces water by
removing some ions and adding an agent which increases the viscosity of
the water and/or increases an oil recovery from the formation, and
injects the water into the well. In another embodiment, there is
disclosed a system comprising a first well drilled into an underground
formation; a production facility at a topside of a first well; a water
production facility connected to the production facility; a second well
drilled into the underground formation; wherein the water production
facility produces water by removing some ions and adding an agent which
increases the viscosity of the water and/or increases an oil recovery
from the formation, and injects the water into the second well and into
the underground formation. In some embodiments, the first well is a
distance of 50 meters to 2000 meters from the second well. In some
embodiments, the underground formation is beneath a body of water. In
some embodiments, the production facility is floating on a body of water,
such as a production platform. In some embodiments, the system also
includes a water supply and a water pumping apparatus, adapted to pump
water to the water production facility. In some embodiments, the water
production facility has an input water having a total dissolved salts
value of at least 15,000 parts per million, expressed as sodium chloride
dissolved. In some embodiments, the agent comprises one or more materials
selected from the group consisting of: alkyl xylene sulfonates; alkyl
benzene sulfonates; C18 alkyl toluene sulfonates; alkyl aryl sulfonates;
alkyl naphthalene sulfonates; polyethoxyalkylated alkyl sulfate; Sodium
lauryl ethoxy sulfate; Ethoxylated styrylaryloxy sulfonate;
Polyoxyethylene alkylether sulfonate; Carboxymethylated ethoxylate;
Nonylphenol polyethyleneoxide ether sulfate; Petroleum Sulfonates;
Alkoxylated alkylphenol sulfonates; Alpha-olefin sulfonate C12-16;
Alpha-olefin sulfonate C14-16; Alpha-olefin sulfonate C16-18; Internal
olefin sulfonate C15-18; Internal olefin sulfonate C17-20; Sodium alkyl
sulfate; Sodium methyl 2-sulfonyllaurate; Sodium lignosulfonate; Alkyl
propoxy sulfates; Hydrolyzed Polyacrylamide; polyvinylpyrrolidones;
hydroxyethyl celluloses; cellulose sulphate esters; guar gums; xanthans;
scleroglucans; polyacrylic acid polymers; alkyl acrylamide polymers;
polysaccharide polymers; copolymers of acrylamides and acrylic acid or
sodium acrylate; N-sulfohydrocarbon-substituted acrylamides;
biopolysaccharides; copolymers of acrylamide and sodium acrylate;
solutions of partially saponified polyacrylamide; copolymers containing
from 99 to 50 percent by weight acrylamide units and from 1 to 50 percent
by weight acrylate units; polyacrylamide containing up to 10 mole percent
carboxylate groups; random copolymers of 90 mole percent or more
acrylamide and ten mole percent or less acrylic acid or acrylic acid
salts; homopolymers of N-methyl-acrylamide or N,N-dimethylacrylamide;
copolymers or terpolymers of 0.1-99.9 mole percent acrylamide and
99.9-0.1 mole percent N-methylacrylamide and/or N,N-dimethylacrylamide;
poly(methylmethacrylate), poly(ethylmethacrylate), poly(methacrylamide),
poly(methylacrylate), poly(ethylacrylate), poly(N-methylmethacrylamide)
and/or poly(N,N-dimethylacrylamide); quaternary polymers with nitrogen or
phosphorous as the quaternary or cationic atom with an aliphatic,
cycloaliphatic or aromatic chain, where trivalent or tertiary sulfur may
be substituted for the quaternary nitrogen or phosphorous in the
polymers; and/or a polar and generally soluble polymer in polar solvents.
In some embodiments, at least one well has been fractured with a viscous
liquid and a propping agent such as sand. In some embodiments, at least
one well comprises a diameter from 10 to 25 cm.

[0019]In one embodiment, there is disclosed a method comprising removing
some ions from water; adding an agent to the water which increases the
viscosity of the water and/or increases oil recovery from an underground
formation; and injecting the water with the agent into the underground
formation. In some embodiments, the processed water is recycled by being
produced with oil and/or gas and separated, and then re-injected into the
formation. In some embodiments, one or more of aromatics, chlorinated
hydrocarbons, other hydrocarbons, water, carbon dioxide, carbon monoxide,
or mixtures thereof are mixed with the processed water prior to being
injected into the formation. In some embodiments, the processed water is
heated prior to being injected into the formation. In some embodiments,
the processed water is heated while within the formation. In some
embodiments, the processed water is heated with hot water, steam and/or a
non-aqueous liquid and/or gas injected into the formation. In some
embodiments, removing some cations from water comprises removing some
divalent cations. In some embodiments, removing some cations from water
comprises removing some divalent cations and then removing some
monovalent cations. In some embodiments, removing some cations from water
comprises removing some divalent cations and then removing some
monovalent cations, and then adding back some divalent cations. In some
embodiments, another material is injected into the formation after the
processed water was injected. In some embodiments, the another material
is selected from the group consisting of air, produced water, salt water,
sea water, fresh water, steam, carbon dioxide, and/or mixtures thereof.
In some embodiments, the processed water is injected from 10 to 100 bars
above the reservoir pressure. In some embodiments, the oil in the
underground formation prior to water being injected has a viscosity from
5 cp to 10,000 cp. In some embodiments, the oil in the underground
formation prior to water being injected has a viscosity from 500 cp to
5,000 cp. In some embodiments, the underground formation has a
permeability from 5 to 0.0001 Darcy. In some embodiments, the underground
formation has a permeability from 1 to 0.001 Darcy. In some embodiments,
producing and/or injecting are done into a vertical and/or a horizontal
well. In some embodiments, input water has a total dissolved salts value
of at least 15,000 parts per million, expressed as sodium chloride
dissolved, prior to the removing some cations from the water. In some
embodiments, the agent comprises one or more materials selected from the
group consisting of: alkyl xylene sulfonates; alkyl benzene sulfonates;
C18 alkyl toluene sulfonates; alkyl aryl sulfonates; alkyl naphthalene
sulfonates; polyethoxyalkylated alkyl sulfate; Sodium lauryl ethoxy
sulfate; Ethoxylated styrylaryloxy sulfonate; Polyoxyethylene alkylether
sulfonate; Carboxymethylated ethoxylate; Nonylphenol polyethyleneoxide
ether sulfate; Petroleum Sulfonates; Alkoxylated alkylphenol sulfonates;
Alpha-olefin sulfonate C12-16; Alpha-olefin sulfonate C14-16;
Alpha-olefin sulfonate C16-18; Internal olefin sulfonate C15-18; Internal
olefin sulfonate C17-20; Sodium alkyl sulfate; Sodium methyl
2-sulfonyllaurate; Sodium lignosulfonate; Alkyl propoxy sulfates;
Hydrolyzed Polyacrylamide; polyvinylpyrrolidones; hydroxyethyl
celluloses; cellulose sulphate esters; guar gums; xanthans;
scleroglucans; polyacrylic acid polymers; alkyl acrylamide polymers;
polysaccharide polymers; copolymers of acrylamides and acrylic acid or
sodium acrylate; N-sulfohydrocarbon-substituted acrylamides;
biopolysaccharides; copolymers of acrylamide and sodium acrylate;
solutions of partially saponified polyacrylamide; copolymers containing
from 99 to 50 percent by weight acrylamide units and from 1 to 50 percent
by weight acrylate units; polyacrylamide containing up to 10 mole percent
carboxylate groups; random copolymers of 90 mole percent or more
acrylamide and ten mole percent or less acrylic acid or acrylic acid
salts; homopolymers of N-methyl-acrylamide or N,N-dimethylacrylamide;
copolymers or terpolymers of 0.1-99.9 mole percent acrylamide and
99.9-0.1 mole percent N-methylacrylamide and/or N,N-dimethylacrylamide;
poly(methylmethacrylate), poly(ethylmethacrylate), poly(methacrylamide),
poly(methylacrylate), poly(ethylacrylate), poly(N-methylmethacrylamide)
and/or poly(N,N-dimethylacrylamide); quaternary polymers with nitrogen or
phosphorous as the quaternary or cationic atom with an aliphatic,
cycloaliphatic or aromatic chain, where trivalent or tertiary sulfur may
be substituted for the quaternary nitrogen or phosphorous in the
polymers; and/or a polar and generally soluble polymer in polar solvents.

[0020]Referring now to FIG. 2, in one embodiment of the invention, system
200 is illustrated. System 200 includes body of water 202, formation 204,
formation 206, and formation 208. Production facility 210 may be provided
at the surface of body of water 202. Well 212 traverses body of water 202
and formation 204, and has openings at formation 206. Portions of
formation may be fractured and/or perforated as shown at 214. As oil and
gas is produced from formation 206 it enters portions 214, and travels up
well 212 to production facility 210. Gas and liquid may be separated, and
gas may be sent to gas storage 216, and liquid may be sent to liquid
storage 218, and water may be sent to water production 230. Production
facility 210 is able to process water, for example from body of water 202
and/or well 212, which may be processed and stored in water production
230. Water from well 212 may be sent to water production 230. Processed
water may be pumped down well 232, to fractured portions 234 of formation
206. Water traverses formation 206 to aid in the production of oil and
gas, and then the water the oil and gas may be all produced to well 212,
to production facility 210. Water may then be recycled, for example by
returning water to water production 230, where it may be processed, then
re-injected into well 232.

[0021]Hydrocarbons, such as oil and/or gas, may be recovered from the
earth's subsurface formation 206 through production wellbore 212 that
penetrate hydrocarbon-bearing formations or reservoirs. Perforations may
be made from the production wellbore 206 to portions of the formation 214
to facilitate flow of the hydrocarbons from the hydrocarbon-bearing
formations to the production wellbores. Water may be injected under
pressure into injection zones 234 formed in the subsurface formation 206
to stimulate hydrocarbon production through the production wells in a
field. Water may be injected by itself as a component of miscible or
immiscible displacement fluids. Sea water (for offshore wells) and brine
produced from the same or nearby formations (for onshore wells) may be
used as the water source. Such water may contain amounts (concentration)
of precursor ions, such as divalent sulfate (SO4.sup.-), which may
form insoluble salts when they come in contact with cations, such as
Ba++, Sr++ and Ca++, resident in the formations. The
resulting salts (BaSO4, SrSO4 and CaSO4) can be relatively
insoluble at subsurface formation temperature and pressure. Such salts
may precipitate out of the solution. The precipitation of the insoluble
salts may accumulate and consequently plug the subsurface fluid
passageways. The plugging effects may be most severe in passageways in
the formation near the injection well 232 and at the perforations of the
production well 212. Solubility of the insoluble salts may further
decrease as the injection water is produced to the surface through the
production well 212, due to the reduction of the temperature and pressure
as the fluids move to the surface through the production well. Subsurface
or formation fluid passageways may include pores in the formation matrix,
fractures, voids, cavities, vugs, perforations and fluid passages through
the wells, including cased and uncased wells, tubings and other fluid
paths in the wells. Precipitates may include insoluble salts, crystals or
scale. Plugging may include reduction in the porosity and/or permeability
of fluid passageways and the tubulars used in producing the well fluids
and processing of those fluids. Injection water may include any fluid
containing water that is injected into a subsurface formation to
facilitate recovery of hydrocarbons from subsurface formations.

[0022]One purpose of injection well 232 is to aid the flow of hydrocarbons
from the reservoir to production well 212. One method is to inject water
under pressure adjacent to a production zone to cause the hydrocarbons
trapped in the formation 206 to move toward the production well 212.

[0023]Referring now to FIG. 3, in some embodiments of the invention, a
system 300 for water production 330 is illustrated. Water production 330
has an input of unprocessed water, for example water from a body of
water, from a well, seawater, city water supply, or another water supply.
At 334 some cations may be removed from raw water 302, for example
monovalent cations, or multivalent cations, such as divalent or trivalent
cations. At 340, an agent may be added to partially processed water in
order to increase the viscosity of the water. Processed water 303 is then
produced from water production 330.

[0024]Referring now to FIG. 4, in some embodiments of the invention,
system 400 for water production 430 is illustrated. Water production 430
has an input of unprocessed water 402, for example water from the body of
water from a well, sea water, city water supply, or another water supply.
At 432, primary filtration may be accomplished to remove solids from
water. At 433 sulphates (SO4) may be removed. At 434, some divalent
cations may be removed, for example from about 60 to about 99% of the
divalent cations present. Divalent cations which may be removed include
magnesium (Mg), calcium (Ca), iron (Fe) and/or strontium (Sr).

[0025]In some embodiments, 433 and 434 may be performed at the same time
with a nanofiltration membrane system.

[0026]At 436, some monovalent ions may be removed, for example from about
60 to about 99% of the cations present, such as sodium (Na), and/or
potassium (K), along with the associated anions, for example chloride,
fluoride, and/or bromide. At 438, some divalent cations may be added back
to water, for instance adding back some magnesium, calcium, and/or
strontium. At 440, an agent may be dissolved into water, where the agent
increases the viscosity of the water. Processed water 403 may be produced
by water production 430.

[0027]In some embodiments, water production 330 and/or 430 may use a
membrane based system, for example reverse osmosis (RO) and/or
nanofiltration (NF) technology, such as are used for seawater
desalination, filtration, and/or purification.

[0028]The driving force for permeation for membrane separation may be the
net pressure across the membrane; this is defined as the feed pressure
minus the permeate or back pressure, less the difference between the
osmotic pressure of the feed and the osmotic pressure of the permeate.

[0029]U.S. Pat. No. 4,723,603 employs NF membranes for specific removal of
sulfate from seawater. Sulfates may be removed by NF membranes, and the
NF permeate, may be rich in sodium chloride but deficient in sulfate.
Such sulfate-free water may prevent the formation of barium sulfate,
which has low solubility and can cause clogging. U.S. Pat. No. 4,723,603
is herein incorporated by reference in its entirety.

[0030]U.S. Pat. No. 4,341,629 discloses desalinating seawater by using two
RO modules, which can include the same membrane, e.g. a 90% rejection
cellulose triacetate (CTA) RO membrane, or two different membranes, e.g.
an 80% rejection CTA membrane and a 98% rejection CTA membrane. U.S. Pat.
No. 4,341,629 is herein incorporated by reference in its entirety.

[0031]U.S. Pat. No. 5,238,574 discloses the use of a multiplicity of RO
membrane modules to process seawater. For example, a first low-pressure
RO membrane may be followed by a high pressure RO membrane, or a series
of low pressure RO membranes can be used, to either provide permeate of
varying water quality or simply to produce a combined permeate where the
concentrate stream from one module becomes the feedstream for the next
module in series. U.S. Pat. No. 5,238,574 is herein incorporated by
reference in its entirety.

[0032]In some embodiments, system 400 may include unprocessed water 402,
from an aqueous feed source such as seawater from the ocean, or any
saline water source having some divalent and monovalent ions, such as
produced water from a well. As one example, raw seawater may be taken
from the ocean, either from a sea well or from an open intake, and
initially subjected to primary filtration 432 using a large particle
strainer (not shown), and/or multi-media filters, which might be
typically sand and/or anthracite coal, optionally followed by a cartridge
filtration.

[0033]In some embodiments, processes 433, 434, and/or 436 can include one
or a plurality of RO cartridges which may be located downstream of one or
a plurality of NF cartridges. RO cartridges and/or NF cartridges may be
spirally wound semipermeable membrane cartridges, or cartridges made
using hollow fiber technology having suitable membrane characteristics.
For example, E. I. DuPont sells RO cartridges of hollow fine fiber (HFF)
type, which are marketed by DuPont as their HFF B-9 cartridges and which
may be used. A spirally wound semipermeable membrane cartridge may
include a plurality of leaves which are individual envelopes of
sheet-like semipermeable membrane material that sandwich therebetween a
layer of porous permeate carrying material, such as polyester fibrous
sheet material. The semipermeable membrane material may be any of those
commercially available materials. Interleaved between adjacent leaves may
be lengths of spacer material, which may be woven or other open mesh,
screen-like crosswise designs of synthetic filaments, e.g. cross-extruded
filaments of polypropylene or the like such as those sold under the trade
names Vexar and Nalle, that provide flow passageways for the feed water
being pumped from end to end through a pressure vessel. A lay-up of such
alternating leaves and spacer sheets may then be spirally wound about a
hollow tube having a porous sidewall to create a right circular
cylindrical cartridge.

[0034]One spirally wound separation cartridge is disclosed in U.S. Pat.
No. 4,842,736, the disclosure of which is incorporated herein by
reference, which provides a plurality of spiral feed passageways which
extend axially from end to end of the ultimate cartridge, through which
passageways the feed liquid being treated flows in an axial direction.
Internally within the membrane envelopes, the permeating liquid flows
along a spiral path inward in a carrier material until it reaches the
porous central tube where it collects and through which it then flows
axially to the outlet.

[0035]In some embodiments, RO cartridges and/or NF cartridges may be
selected so as to accomplish the desired overall function of producing a
stream of processed water having the desired ionic concentrations from
seawater or the like. RO elements or cartridges may be selected from
suitable semipermeable membranes of the polyamide composite membrane
variety, wherein a thin film of polyamide may be interfacially formed on
a porous polysulfone support or the like that may be in turn formed on a
highly porous fibrous backing material. RO membranes may be designed to
reject more than about 95% of dissolved salts, for example about 98% or
more.

[0036]Suitable commercially available RO membranes include those sold as
AG8040F and AG8040-400 by Osmonics; SW30 Series and LE by Dow-FilmTec; as
Desal-11 by Desalination Systems, Inc.; as ESPA by Hydranautics; as ULP
by Fluid Systems, Inc.; and as ACM by TriSep Corporation.

[0037]NF membranes may be employed which are designed to selectively
reject divalent or larger ions, and the NF elements or cartridges which
are used may reject a minimum of about 80%, for example more than about
90%, or about 95%, or about 98% of the divalent or larger ions in an
aqueous feed. The NF membrane may also at least moderately reduces the
monovalent ion content, for example less than about 70%, or less than
about 50%, or less than about 30%, or less than about 20% of the
monovalent ion content. Suitable commercially available NF membranes can
be purchased either in sheet form or in finished spirally wound
cartridges, and include those sold as Seasoft 8040DK, 8040DL, and Sesal
DS-5 by Osmonics; as NF200 Series and NF-55, NF-70 and as NF-90 by
Dow-Film Tec; as DS-5 and DS-51 by Desalination Systems, Inc., as
ESNA-400 by Hydranautics; and as TFCS by Fluid Systems, Inc.

[0038]In some embodiments, a mechanical method, such as passing the
unprocessed water 402 through a nano-filtration membrane, may be used to
remove ions from the water at the surface before injecting it into the
wellbore and/or adding an agent 440. Sea water may contain from about
2700 to about 2800 ppm of divalent SO4.sup.-. The nano-filtration
membrane process may reduce this concentration 433 to about 20 to about
150 ppm. A 99% reduction in sulfate content may be achievable.

[0039]In some embodiments, chemicals and/or additives may be injected into
the untreated water 402 to inhibit the in-situ growth of crystals from
insoluble salt precipitation. A variety of additives are injected into
the injection water at the surface or directly into an injection well.
Production wells may also often be treated with back-flow of fresh brine
containing additives to prevent plugging of the passageways.

[0040]In some embodiments, salt water may be processed 433, 434, and/or
436 by multistage flash distillation, multieffect distillation, reverse
osmosis and/or vapor compression distillation. Membrane technologies have
been used in the pre-treatment of salt water to reduce the high ionic
content of salt water relative to fresh water. Ion selective membranes
may be used which selectively prevent certain ions from passing across it
while at the same time allowing the water and other ions to pass across
it. The selectivity of a membrane may be a function of the particular
properties of the membrane, including the pore size or electrical charge
of the membrane. Accordingly, any of the known and commercially available
ion selective membranes which meet these criteria can be used. For
example, a polyamide membrane is particularly effective for selectively
preventing sulfate, calcium, magnesium and bicarbonate ions from passing
across it, and could be used for processes 433 and/or 434. A polyamide
membrane having the trade name SR90-400 (Film Tec Corporation) or
Hydranautics CTC-1 may be used.

[0041]In some embodiments of the invention, unprocessed water 402
containing a high concentration of hardness ions (for example divalent
cations) is passed through an ion selective membrane 434 to form a
softened salt water having a reduced concentration of hardness ions. The
softened salt water is fed to a desalination system 436. Then, some of
the hardness ions may be added back to the water at 438, and a
viscosifier added at 440.

[0042]Microfiltration (MF), ultrafiltration (UF), nanofiltration (NF), and
reverse osmosis (RO) are all pressure-driven separation processes
allowing a broad range of neutral or ionic molecules to be removed from
fluids. Microfiltration may be used for removal of suspended particles
greater than about 0.1 microns. Ultrafiltration may be used to exclude
dissolved molecules greater than about 5,000 molecular weight.
Nanofiltration membranes may be used for passing at least some salts but
having high rejection of organic compounds having molecular weights
greater than approximately 200 Daltons. Reverse osmosis membranes may be
used for high rejection of almost all species. While NF and RO are both
capable of excluding salts, they typically differ in selectivity. NF
membranes commonly pass monovalent ions while maintaining high rejection
of divalent ions. By contrast, reverse osmosis membranes are relatively
impermeable to almost all ions, including monovalent ions such as sodium
and chloride ions. NF membranes have sometimes been described as "loose"
RO membranes. One suitable membrane capable of removing dissolved salts
from water is the cellulose acetate membrane, with selectivity resulting
from a thin discriminating layer that is supported on a thicker, more
porous layer of the same material. Another suitable membrane is made of
piperazine or substituted piperazine. Other suitable membranes include
polymers such as the commercial FilmTec NF40 NF membranes.

[0043]In some embodiments, a spiral-wound filter cartridge may be used to
incorporate large amounts of RO or NF membrane into a small volume. Such
an element can be made by wrapping feed spacer sheets, membrane sheets,
and permeate spacer sheets around a perforated permeate tube.

[0044]In some embodiments, interfacial polymerization may be used to make
thin film composite membranes for RO and NF separations. This process is
commonly performed as a polycondensation between amines and either acid
chlorides or isocyanates.

[0045]Reverse osmosis membranes may have high rejection of virtually all
ions, including sodium and chloride. NF membranes are often characterized
as those having a substantial passage of neutral molecules having
molecular weights less than 200 daltons and monovalent ions. NF membranes
still commonly possess high rejection of divalent ions due to charge
interactions. Membranes having a continuum of properties between RO and
NF can also be produced. In addition to high rejection of at least one
species, commercial membranes often possess high water permeability.

[0046]In some embodiments, membranes for RO and/or NF may be
piperazine-based membranes, where at least 60% of amine-containing
monomers incorporated into the polymer may be piperazine or piperazine
derivative molecules. One typical example of a piperazine-based membrane
is the FilmTec NF40 NF membrane, which has been made by contacting
piperazine and TMC in the presence of an acid acceptor,
N,N-dimethylpiperazine. The FilmTec commercial membranes NF45 and SR90
have been made by similar processes, with additional proprietary
chemicals added to the water and/or organic phase. A particularly useful
property of some membranes is the ability to selectively remove some
molecules while retaining others. For example, the dairy industry has
used piperazine-based membranes to concentrate large neutral molecules
(whey and lactose) while removing minerals. In other cases it is desired
to pass monovalent salts while maintaining high rejection of divalent
ions.

[0047]In some embodiments, processes 334, 433, and/or 434 may use a NF
device, such as a membrane. In some embodiments, processes 334 and/or 436
may use a RO device, such as a membrane.

[0048]In some embodiments of the invention, agents for increasing the
viscosity of a flooding fluid added at 340 and/or 440 may be
water-soluble or water-dispersible, high molecular weight polymers.

[0098]In some embodiments, the term "polyacrylamide" includes any
cationic, anionic, nonionic or amphoteric polymer that may be comprised
of acrylamide or methacrylamide recurring units. The polyacrylamides may
be vinyl-addition polymers and may be prepared by methods such as by
homopolymerization of acrylamide or by copolymerization of acrylamide
with cationic, anionic, and/or nonionic comonomers. Suitable cationic
comonomers include diallyldialkylammonium halides, the acid and
quaternary salts of dialkylaminoalkyl(alk)acrylates and
dialkylaminoalkyl(alk)acrylamides, for example the methyl chloride,
benzyl chloride and dimethyl sulfate quaternary salts of
dimethylaminoethylacrylate, dimethylaminoethylmethacrylate,
dimethylaminoethylacrylamide, dimethylaminoethylmethacrylamide, and
diethylaminoethylacrylate, for example diallyidimethylammonium chloride
and the methyl chloride quaternary salt of dimethylaminoethylacrylate.
Anionic comonomers may include acrylic acid, methacrylic acid, and
2-acrylamido-2-methylpropanesulfonic acid, and salts thereof, for example
acrylic acid and sodium acrylate. Nonionic comonomers may include
acrylonitrile and alkyl(meth)acrylates such as methylacrylate,
methylmethacrylate, and ethyl acrylate. The polyacrylamides may also be
formed by post-reaction of polyacrylamides in a manner well-known to
those skilled in the art by reacting the polyacrylamide with a reagent
capable of changing the chemical structure of the polymer. Post-reactions
of polyacrylamide may include hydrolysis with acid or base to produce
hydrolyzed polyacrylamide, Mannich reaction (optionally followed by
quaternization to produce quaternized Mannich polyacrylamide), and
reaction with hydroxylamine (or salt thereof) to produce hydroxamated
polyacrylamide. Cationic and anionic polyacrylamides may be used.

[0099]In some embodiments of the invention, agents for increasing the
viscosity include polymers comprising an N-vinyl lactam and an
unsaturated amide, such as N-vinyl-2-pyrrolidone, including homopolymers,
copolymers and terpolymers, as disclosed in U.S. Pat. No. 6,030,928,
herein incorporated by reference in its entirety. In some embodiments of
the invention, agents for increasing the viscosity include viscosifiers,
such as polymeric thickening agents, that may be added to all or part of
an injected water composition in order to increase the viscosity thereof.

[0100]In some embodiments, agents have a weight average molecular weight
of from about 1×106 to about 40×106, for example
from about 5×106 to about 30×106, or for example
from about from about 4 to about 7 million or from about 15 to about 30
million. In some embodiments, the molecular weight is about 100,000 or
greater, for example about 1,000,000 or greater, such as about 10,000,000
or greater. Molecular weights may be determined by light scattering,
using commercially available instrumentation and techniques that are
known in the art.

[0101]In some embodiments, agents are sold by a variety of companies
including Dow Chemical Co. in Midland, Mich. One agent may be
Alcoflood® 1235, a water soluble polymeric viscosifier available from
Ciba Specialty Chemicals in Tarrytown, N.Y.

[0102]In some embodiments, the agent may be added at 440 to the waterflood
at a concentration of about 0.001% to about 1% by weight of the total
solution.

[0103]The reduction of the mobility of a fluid in a porous media such as
an oil-bearing reservoir can be accomplished by increasing the viscosity
of the fluid, decreasing the permeability of the porous media, or by a
combination of both. The agent may both increase the viscosity of water
and/or reduce the permeability of a reservoir as a solution flows through
it. The extent to which a particular concentration of a given agent
performs these two functions may be very roughly a function of the
agent's average molecular weight. The lower the permeability of the
reservoir, the lower may be the average molecular weight of the agent
which can be injected without significant wellbore plugging. For a given
formation, however, it is entirely possible to have two partially
hydrolyzed polyacrylamide solutions of the same average molecular weight
which will exhibit radically different efficiencies for mobility control
purposes. Where the molecular weight distribution of a polymer is
relatively narrow, as is the case with some polymers, substantially all
of the polymer may be effective in infectivity and mobility control. If
the molecular weight distribution is broad, as is the case with some
polymers, the mobility may be adversely affected by the lower molecular
weight molecules in the polymer mixture, while the higher molecular
weight molecules of the polymer indicate the presence of gel-like species
that may result in wellbore plugging.

[0104]In some embodiments of the invention, agents for increasing the
viscosity of the flooding water achieve a solution viscosity of at least
about 10 centipoises at room temperature, and/or reduce the permeability
of rock to the flooding water by adsorbing on the rock in the formation.

[0105]In some embodiments, agents may be selected based on viscosity
retention, porous media flow performance, high temperature, high
salinity, and high pressure conditions. In some embodiments, a solution
with an agent should be at least five times more viscous than sea water.

[0106]In some embodiments, agents can be at least partially dissolved in
various fluids, including for example an aqueous fluid, or in a fluid
containing at least one composition selected from bases, polymeric
viscosifiers, surfactants and cosurfactants, and combinations of any two
or more of said compositions. The agents can be crosslinked with various
crosslinking agents. The agents may be water-soluble or
water-dispersible. In some embodiments of the invention, a composition
includes an agent for increasing the viscosity, an aqueous fluid, and one
or more of: surfactants, cosurfactants, corrosion inhibitors, oxygen
scavengers, bactericides, and any combination thereof.

[0107]In some embodiments of the invention, processed water 303 and/or 403
may be combined with one or more of the aromatics, for example, benzene,
toluene, or xylene; turpentine; tetralin; chlorinated hydrocarbons, for
example, carbon tetrachloride or methlyene chloride; or other
hydrocarbons, for example C5-C10 hydrocarbons and/or alcohols;
steam; or sulfur compounds, for example, hydrogen sulfide, and then
injected into a formation for enhanced oil recovery. For example, a
mixture of processed water with an agent for increasing the viscosity
mixed with alcohol, may be injected into a formation.

[0108]In some embodiments, a mixture of an agent and water may be
subjected to shear forces in dynamic liquid dispersing or pumping devices
such as centrifugal pumps. The mixtures can also be pumped in a loop so
that they pass through the centrifugal pump several times until the
desired polymer properties are obtained. Dynamic dispersing and pumping
devices may be hydrodynamic flow machines, for example single- or
multiple-stage rotary centrifugal pumps such as radial centrifugal pumps.
Turbulent flow conditions are flow conditions characterized by irregular
variations in the velocity of the individual liquid particles. A mixture
may be passed through static cutting units with available water in order
to provide a uniform slurry of particulate gel solids having a desired
solids content without substantially degrading the agent, for example,
reducing its molecular weight. The gel slurry resulting from passage
through the static units may be either (a) introduced into a holding tank
with gentle stirring for about 1-4 hours until the gel disappears and the
agent dissolves to give a homogeneous solution concentrate at room
temperature or slightly below, e.g., 15-20 C, or (b) the gel slurry may
be fed continuously into a series of multiple hold tanks with sufficient
overall residence time to form the homogeneous solution concentrate by
the last hold tank. The homogeneous solution concentrate can then be
passed through standard static mixers with available water for final
dilution.

[0109]In some embodiments, the agent may be a polymer that may be prepared
in the presence of crosslinking or branching agents, such as
methylenebisacrylamide, and/or in the presence of chain transfer agents,
such as isopropanol and lactic acid. As the amount of crosslinking agent
is increased, the resulting aqueous composition of dispersed polymer
tends to contain larger amounts of water-swellable polymer. As the amount
of crosslinking agent is decreased, the resulting aqueous composition of
dispersed polymer tends to contain lesser amounts of water-swellable
polymer. Chain transfer agents tend to reduce polymer molecular weight
and to render soluble polymers which would otherwise be water-swellable
because of the presence of crosslinking agents. The aqueous compositions
of the instant invention may contain water-soluble dispersed polymer or
water-swellable dispersed polymer, or mixtures thereof.

[0110]In some embodiments, the agent may be a polymer, such as
polyacrylamide, that may be prepared by using techniques such as
polymerization in solution, water-in-oil emulsion, water-in-oil
microemulsion or aqueous dispersion, for example water-in-oil emulsion or
water-in-oil microemulsion. Polyacrylamide particles may be formed by
methods such as by grinding or comminution of a solution-polymerized mass
of dry polyacrylamide. Spray-dried polyacrylamide particles may be used
and may be formed by spray-drying a polyacrylamide-containing dispersion,
water-in-oil emulsion, or water-in-oil microemulsion.

[0111]In some embodiments, the agent may be a polymer, which may be mixed
with water by contacting of the polymer particles with the moving stream
of water so that it results in an aqueous composition comprised of about
0.01% or greater of dispersed polymer, for example 0.05% or greater, for
example 0.1% or greater, for example 0.2% or greater, by weight based on
total weight of said aqueous composition. In some cases the aqueous
composition may contain more than 5% of dispersed polymer by weight,
based on total weight of aqueous composition, but in other cases contains
about 5% or less of dispersed polymer, for example about 2% or less, for
example about 1% or less, on the same basis.

[0112]In some embodiments of the invention, agents for increasing the
viscosity of the water include a small but effective amount of polymer
used to produce the desired viscosity or other properties in the
injection fluid. Based upon the properties of the formation and the
intended nature and duration of the process, the type and amount of the
agent may be selected to achieve the desired effects over the appropriate
time period. In some embodiments, the amount of agent used will be in the
range of from about 500 ppm to about 10,000 ppm, for example about 1,000
ppm to about 3,000 ppm, based on the weight of the injection fluid.
Generally, there will be selected an economical amount and type of
polymer to produce the desired effect for the required time.

[0113]In some embodiments of the invention, a composition comprising at
least one water-soluble polymer may be prepared by combining at least one
water-soluble polymer together in any sequence. The amount of water
soluble polymer may be about 200 to about 10,000 ppm, for example about
250-500 ppm based on the entire combination. When the composition further
comprises aqueous fluid, the aqueous fluid utilized will comprise or
contain water and may be about 88 to about 99.91 wt % of the final
combination. The composition may also contain other solvents, alcohols,
and/or salts.

[0114]In some embodiments, the polymer solutions may contain the polymers
in concentrations up to about 5000 ppm. Here, the upper concentration
limit may be only due to the increasing viscosity, and the lower limit
may be based on the increasing costs for recovery using larger amounts of
more dilute solutions. For this reason, it may be preferable to use
solutions having a polymer content up to about 3000 ppm, for example a
polymer content from about 2000 ppm to about 3000 ppm. These solutions
are then diluted after treatment in accordance with the invention to
concentrations required for use of from about 300 ppm to about 2000 ppm.

[0115]Water may be commonly injected into subterranean hydrocarbon-bearing
formations by itself or as a component of miscible or immiscible
displacement fluids to recover hydrocarbons therefrom. Unprocessed water
302 and/or 402 can be obtained from a number of sources including brine
produced from the same formation, brine produced from remote formations,
or sea water. All of these waters may have a high ionic content relative
to fresh water. Some ions present in unprocessed water 302 and/or 402 can
benefit hydrocarbon production, for example, certain combinations and
concentrations of cations and anions, including K+, Na+,
Cl.sup.-, Br.sup.-, and/or OH.sup.-, can stabilize clay to varying
degrees in a formation susceptible to clay damage from swelling or
particle migration. Other ions (or the same ions that benefit hydrocarbon
production) present in the unprocessed water 302 and/or 402 can produce
harmful effects in situ, for example, divalent SO4.sup.- anions in
the injection water may be particularly problematic because
SO4.sup.- may form salts with cations already present in the
formation, such as Ba++. The resulting salts can be relatively
insoluble at the formation temperatures and pressures. Consequently they
may precipitate out of solution in situ. Solubility of the salts further
decreases as the injection water may be produced to the surface with the
hydrocarbons because of pressure and temperature decreases in the
production well. The precipitates of the insoluble salts may accumulate
in subterranean fluid passageways as crystalline structures, which
ultimately plug the passageways and reduce hydrocarbon production. The
effects of plugging may be most severe in passageways located in the
formation near wellbores and in production wells where it may be more
difficult for the produced fluids to circumvent blocked passageways.

[0116]In some embodiments of the invention, processed water or a processed
water mixture 303 and/or 403 may be injected into formation 206, produced
from the formation 206, and then recovered from the oil and gas, for
example, by a centrifuge or gravity separator, and then processing the
water at water production 230, then the processed water or a processed
water mixture 303 and/or 403 may be re-injected into the formation 206.

[0117]In some embodiments of the invention, processed water or a processed
water mixture 303 and/or 403 may be injected into an oil-bearing
formation 206, optionally preceded by and/or followed by a flush, such as
with seawater, a surfactant solution, a hydrocarbon fluid, a brine
solution, or fresh water.

[0118]In some embodiments of the invention, processed water or a processed
water mixture 303 and/or 403 may be used to improve oil recovery. The
processed water or a processed water mixture 303 and/or 403 may be
utilized to drive or push the now oil bearing surfactant flood out of the
reservoir, thereby "sweeping" crude oil out of the reservoir. The
processed water or a processed water mixture 303 and/or 403 may have a
viscosity that helps to prevent what is referred to in the industry as
channeling or "fingering", thus improving sweep efficiency. Oil may be
recovered at production well 212 spaced apart from injection well 232 as
processed water or a processed water mixture 303 and/or 403 pushes the
oil out of the pores in formation 206 and to the production well 212.
Once the oil/drive fluid reaches the surface, it may be put into holding
tanks 218, allowing the oil to separate from the water through the
natural forces of gravity.

[0119]The amount of oil recovered may be measured as a function of the
original oil in place (OOIC). The amount of oil recovered may be greater
than about 5% by weight of the original oil in place, for example 10% or
greater by weight of the original oil in place, or 15% or greater by
weight of the original oil in place.

[0120]The process and system may be useful for the displacement recovery
of petroleum from oil-bearing formations. Such recovery encompasses
methods in which the oil may be removed from an oil-bearing formation
through the action of a displacement fluid or a gas. Thus, the recovery
may be secondary, where the reservoir hydrocarbons have been
substantially depleted by primary recovery mechanisms, or it may be
tertiary, where the polymer solution may be injected after injection of
conventionally used displacement fluids. Other uses for the processed
water or a processed water mixture 303 and/or 403 prepared by the process
and system of the invention include near wellbore injection treatments,
and injection along interiors of pipelines to promote pipelining of high
viscosity crude oil. The processed water or a processed water mixture 303
and/or 403 can also be used as hydraulic fracture fluid additives, fluid
diversion chemicals, and loss circulation additives, to mention a few.

[0121]Those of skill in the art will appreciate that many modifications
and variations are possible in terms of the disclosed embodiments,
configurations, materials and methods without departing from their spirit
and scope. Accordingly, the scope of the claims appended hereafter and
their functional equivalents should not be limited by particular
embodiments described and illustrated herein, as these are merely
exemplary in nature.